Abstract: A method for designing a drill bit that has at least one roller cone and a plurality of cutting elements, including selecting initial bit design parameters. Drilling simulations are then used to determine wear, and the simulated drill bit is changed to reflect the determined wear. Then, at least one design parameter is adjusted. The simulation, determination, change of the simulated drill bit, and adjustment may be repeated until at least one performance parameter of the drill bit is optimized. A drill bit can be designed using such a method.

Abstract: An apparatus and method for monitoring and reporting downhole bit failure. Sensors are located on a sub assembly (which is separate from the drill bit itself but located above it on the drill string). Strain measurements are taken from the sensors to detect changes in induced bending and axial stresses which are related to a roller cone bearing failure. As a cone begins to fail, the average share of the total load on the bit that the failing cone can support changes, which causes a change in the bending strain induced by the eccentric loading of the cone.

Abstract: A drill bit for use in drilling operations in a wellbore, the drill bit having a bit body including a plurality of bit legs, each supporting a rolling cone cutter; a coupling member formed at an upper portion of said bit body; at least one temperature sensor for monitoring at least one temperature condition of said improved drill bit during drilling operations; and at least one temperature sensor cavity formed in said bit body and adapted for receiving, carrying, and locating said at least one temperature sensor in a particular position relative to said bit body which is empirically determined to optimize temperature sensor discrimination.

Abstract: A drill bit, comprising a bit body, a sensor disposed in the bit body, a single journal removably mounted to the bit body, and a roller cone rotatably mounted to the single journal.

Abstract: A method and apparatus for predicting the performance of a drilling system for the drilling of a well bore in a given formation is disclosed. The method generates a geology model of a given formation. The geology model includes a geology characteristic of the given formation per unit depth. The method also determines a predicted drilling performance for a proposed drilling equipment based on the geology model and specification data of the proposed drilling equipment, wherein the specification data of the proposed drilling equipment is a function of the geology characteristic.

Abstract: A rotary drill bit includes a bit body that includes a plurality of upright legs that terminate in an exterior bearing surface. At least one roller cutter is affixed to a corresponding exterior bearing surface of one of the plurality of legs. The roller cutter has an exterior cutting surface and a base edge and defines an interior bearing surface that is complementary to a corresponding exterior bearing surface. At least one duct is defined by the lower surface of the lateral wall and is adjacent to at least one exterior bearing surface. A plug is disposed in the duct at a distance from the base edge one of the roller cutters so that if either the interior bearing surface or the exterior bearing surface wears beyond a threshold, the plug will cause a remotely-sensible indication of excessive bearing wear to be asserted.

Abstract: An apparatus and method for monitoring and reporting downhole bit failure. Sensors are located on a sub assembly (which is removable from the drill bit) and send data to neural net or other adaptive filter. The neural net uses past sensor readings to predict future sensor readings. The value predicted for the sensors is subtracted from the actual value to produce a prediction error. Increases in prediction error are used to indicate bit failure. The results of this are transmitted to the operator by varying the pressure in the drilling mud flow.

Abstract: An apparatus and accompanying method for monitoring and reporting downhole bit failure. Individual sensors are placed on a sub which is separate from the drill bit itself, and are powered by a vibration driven power system. The sensor readings are used to compute values which represent the ratios of sensor readings on one sensor in relation to the readings of one or more other sensors. This creates a self-calibrating sensor system that accounts for changes in downhole conditions which might cause sensor readings to fluctuate, but which do not indicate failure.

Abstract: The invention is a drill bit that has a bit body, at least one roller cone attached to the bit body and able to rotate with respect to the bit body, and a plurality of cutting elements disposed on the at least one roller cone. At least one bit design parameter is selected so that the cutting elements wear in a selected manner when drilling an earth formation.

Abstract: A system and method for detecting the wear of a roller bit bearing on a roller drill bit body where the roller element has a plurality of cutting elements and is rotatably attached to the roller drill bit body at the bearing. In the invention, a rotation impeder is in between the roller element and roller drill bit body and upon uneven rotation of the roller element which indicates that the roller element bearing may fail, the rotation impeder impedes the rotation of the roller element. The drill rig operator at the surface can cease drilling operations upon detection of the cessation of rotation of the roller element. The rotation impeder can also be seated in a drilling fluid outlet and cause a detectable loss in drilling fluid pressure when dislodged to otherwise cease rotation of the roller drill bit.

Abstract: A system and method for detecting the wear of a roller bit bearing between a roller drill bit body and a roller bit rotatably attached to the roller drill bit body. A valve-plug is placed between the roller drill bit body and roller bit such that the valve-plug is removably fitted in a drilling fluid outlet in the roller drill bit body, and the valve-plug extends into a channel in the roller bit whereby uneven rotation or vibration of the roller bit causes the valve-plug to impact the sides of the channel which removes the valve-plug from the drilling fluid outlet to cause drilling fluid to flow through the drilling fluid outlet. The drop in pressure from the drilling fluid flowing through the drilling fluid outlet indicates that the roller bit is worn and may fail.

Abstract: The invention is a drill bit that has a bit body, at least one roller cone attached to the bit body and able to rotate with respect to the bit body, and a plurality of cutting elements disposed on the at least one roller cone. At least one bit design parameter is selected so that the cutting elements wear in a selected manner when drilling an earth formation. The invention is also a method for designing a drill bit that has at least one roller cone and a plurality of cutting elements. The method includes several steps, beginning with selecting initial bit design parameters. The drill bit is then simulated drilling at least one selected earth formation. The wear induced change in the cutting element geometry is determined and the simulated bit is adjusted to reflect the wear. The selecting, simulating, determining, and adjusting are repeated and at least one bit design parameter of the drill bit is adjusted until at least one performance parameter of the drill bit is optimized.

Abstract: A roller cone drill bit is disclosed which includes at least one roller cone rotatably mounted to a bit body. The bit body includes therein a lubricant reservoir adapted to supply lubricant to bearings on which the roller cone rotates about the bit body. The bit includes a sensor adapted to detect drilling fluid contamination of the lubricant. The bit includes a processor/transmitter operatively coupled to the sensor and adapted to communicate signals corresponding to detected contamination.

Abstract: A drill bit employing a plurality of discrete, post-like diamond grit impregnated cutting structures extending upwardly from abrasive particulate-impregnated blades defining a plurality of fluid passages therebetween on the bit face. PDC cutters with faces oriented in the general direction of bit rotation are placed in the cone of the bit, which is relatively shallow, to promote enhanced drilling efficiency through softer, non-abrasive formations. A plurality of ports, configured to receive nozzles therein are employed for improved drilling fluid flow and distribution. The blades may extend radially in a linear fashion, or be curved and spiral outwardly to the gage to provide increased blade length and enhanced cutting structure redundancy.

Abstract: A method and apparatus for predicting the performance of a drilling system for the drilling of a well bore in a given formation includes generating a geology characteristic of the formation per unit depth according to a prescribed geology model, obtaining specifications of proposed drilling equipment for use in the drilling of the well bore, and predicting a drilling mechanics in response to the specifications as a function of the geology characteristic per unit depth according to a prescribed drilling mechanics model. Responsive to a predicted-drilling mechanics, a controller controls a parameter in the drilling of the well bore. The geology characteristic includes at least rock strength. The specifications include at least a bit specification of a recommended drill bit. Lastly, the predicted drilling mechanics include at least one of bit wear, mechanical efficiency, power, and operating parameters.

Abstract: A bearing failure indicator for sealed and lubricated rolling cutter earth boring drill bits is disclosed. A plurality of cutting inserts, arranged in a plurality of rows, are secured in the rolling cone cutters. At least two of the rolling cone cutters are intermeshing cutters, arranged such that they have intermeshing rows of cutting inserts. A groove is formed in the intermeshing cutters with a row containing a plurality of generally flat top bearing inserts. In the normal operation of the drill bit, the rows of generally flat top bearing inserts do not contribute to the drilling action of the drill bit. However, when a bearing assembly fails in operation, the generally flat top bearing inserts engage the intermeshing rows of inserts in the adjacent intermeshing cutter causing the drilling torque to increase and thereby providing a signal indicating the bearing has failed.

Abstract: An apparatus and accompanying method for monitoring and reporting downhole bit failure. Individual sensors are placed on a sub which is separate from the drill bit itself, and are powered by a vibration driven power system. The sensor readings are used to compute values which represent the ratios of sensor readings on one sensor in relation to the readings of one or more other sensors. This creates a self-calibrating sensor system that accounts for changes in downhole conditions which might cause sensor readings to fluctuate, but which do not indicate failure.

Abstract: An apparatus and method for monitoring and reporting downhole bit failure. Sensors are located on a sub assembly (which is removable from the drill bit) and send data to neural net or other adaptive filter. The neural net uses past sensor readings to predict future sensor readings. The value predicted for the sensors is subtracted from the actual value to produce a prediction error. Increases in prediction error are used to indicate bit failure. The results of this are transmitted to the operator by varying the pressure in the drilling mud flow.

Abstract: A method and apparatus is described for signalling the surface operator about downhole conditions. Sensors located downhole collect data while drilling and the data is processed to determine bit failure, for example. When the sensor data indicates a failure, the pressure of drilling mud is varied using a valve on the downhole unit, and this pressure variance is indicated by a pressure gauge visible to the operator. This pressure change tells the operator a failure has been indicated.

Abstract: An apparatus and method for monitoring and reporting downhole bit failure. Sensors are located on a sub assembly (which is separate from the drill bit itself but located above it on the drill string). Strain measurements are taken from the sensors to detect changes in induced bending and axial stresses which are related to a roller cone bearing failure. As a cone begins to fail, the average share of the total load on the bit that the failing cone can support changes, which causes a change in the bending strain induced by the eccentric loading of the cone.

Abstract: A rotary drill bit includes a bit body that includes a plurality of upright legs that terminate in an exterior bearing surface. At least one roller cutter is affixed to a corresponding exterior bearing surface of one of the plurality of legs. The roller cutter has an exterior cutting surface and a base edge and defines an interior bearing surface that is complementary to a corresponding exterior bearing surface. At least one duct is defined by the lower surface of the lateral wall and is adjacent to at least one exterior bearing surface. A plug is disposed in the duct at a distance from the base edge one of the roller cutters so that if either the interior bearing surface or the exterior bearing surface wears beyond a threshold, the plug will cause a remotely-sensible indication of excessive bearing wear to be asserted.

Abstract: A system and method for detecting the wear of a roller bit bearing between a roller drill bit body and a roller bit rotatably attached to the roller drill bit body. A valve-plug is placed between the roller drill bit body and roller bit such that the valve-plug is removably fitted in a drilling fluid outlet in the roller drill bit body, and the valve-plug extends into a channel in the roller bit whereby uneven rotation or vibration of the roller bit causes the valve-plug to impact the sides of the channel which removes the valve-plug from the drilling fluid outlet to cause drilling fluid to flow through the drilling fluid outlet. The drop in pressure from the drilling fluid flowing through the drilling fluid outlet indicates that the roller bit is worn and may fail.

Abstract: A method and apparatus for predicting the performance of a drilling system for the drilling of a well bore in a given formation includes generating a geology characteristic of the formation per unit depth according to a prescribed geology model, obtaining specifications of proposed drilling equipment for use in the drilling of the well bore, and predicting a drilling mechanics in response to the specifications as a function of the geology characteristic per unit depth according to a prescribed drilling mechanics model. Responsive to a predicted drilling mechanics, a controller controls a parameter in the drilling of the well bore. The geology characteristic includes at least rock strength. The specifications include at least a bit specification of a recommended drill bit. Lastly, the predicted drilling mechanics include at least one of bit wear, mechanical efficiency, power, and operating parameters.

Abstract: An apparatus for measuring the weight and torque on a drill bit operating down hole in a well. The apparatus comprises at least three pockets circumferentially spaced equidistantly around the drill collar of the drill string to which the drill bit is attached. Eight strain gages are equidistantly circumferentially spaced around each of the pockets so as to form first and second sets of strain gages. The strain gages in the first set are connected into one Wheatstone bridge while the gages in the second set are connected in a second bridge. Each of the strain gages that are oriented similarly within each of the pockets are connected in series within a single leg of a bridge so that the output voltage of the bridge is unaffected by bending in the drill string. The output of first bridge is used to determine the weight on the drill bit while the output of the second bridge is used to determine the torque on the drill bit.

Abstract: A method is provided for generating an indicator of potential bit abrasion in a particular wellbore. Forensic wellbore data is obtained from at least one previously drilled wellbore which is determined to be comparable to the particular target wellbore. Typically, the comparable wellbore comprises an “offset” wellbore which is proximate the target wellbore, and which has similar geologic features. An inference engine computer program is provided which consists of executable program instructions. It is adapted to utilize a plurality of wellbore parameters, including the forensic wellbore data. The inference engine includes at least one rule matrix which defines a plurality of fuzzy sets. These fuzzy sets establish correspondence between the plurality of wellbore parameters and the indictor of potential bit abrasion. The inference engine computer program is loaded onto a data processing system. At least the forensic wellbore data is supplied as an input to the inference engine computer program.

Abstract: A method of assaying work of an earth boring bit of a given size and design comprises the steps of drilling a hole with the bit from an initial point to a terminal point. A plurality of electrical incremental actual force signals are generated, each corresponding to a force of the bit over a respective increment of the distance between the initial and terminal points. A plurality of electrical incremental distance signals are also generated, each corresponding to the length of the increment for a respective one of the incremental actual force signals. The incremental actual force signals and the incremental distance signals are processed to produce a value corresponding to the total work done by the bit in drilling from the initial point to the terminal point. Using such a basic work assay, a number of other downhole occurrences and/or conditions can be assayed.

Abstract: A method for determining the existence of a whirling condition during drilling of a borehole provides real time determination of destructive conditions of a bottom hole assembly during drilling. The method measures the acceleration of the bottom hole assembly to determine one or more acceleration values. Sensors also measured with rotation speed of the bottom hole assembly to determine at least one rotation of speed value. Based upon this information calculations are performed to determine a radius or diameter of rotation in the time domain which will indicate and identify the whirling condition within the bottom hole assembly. Types of whirl conditions identifiable are forward and backward whirl with and without slip. The method assumes forward whirl and backward whirl and creates a plot for each then overlaps the plot which provides an accurate representation of the condition of the bottom hole assembly while drilling.

Abstract: A wear indicator is provided for a rotary drilling tool of the type which comprises a bit body having a leading surface for cutting, abrading or reaming a hole in a target substrate material such as a sub-surface formation, the wear indicator comprising or including one or more discrete areas of a visually distinct material to that from which the drilling tool is mainly composed, the visually distinct material being arranged or configured at or adjacent the surface of the bit such that progressive wear of the bit and hence the or each visually distinct discrete area provides a visual indication of surface wear of the tool.

Abstract: A method of assaying work of an earth boring bit of a given size and design comprises the steps of drilling a hole with the bit from an initial point to a terminal point. A plurality of electrical incremental actual force signals are generated, each corresponding to a force of the bit over a respective increment of the distance between the initial and terminal points. A plurality of electrical incremental distance signals are also generated, each corresponding to the length of the increment for a respective one of the incremental actual force signals. The incremental actual force signals and the incremental distance signals are processed to produce a value corresponding to the total work done by the bit in drilling from the initial point to the terminal point. Using such a basic work assay, a number of other downhole occurrences and/or conditions can be assayed.

Abstract: A method and apparatus for predicting the performance of a drilling system for the drilling of a well bore in a given formation includes generating a geology characteristic of the formation per unit depth according to a prescribed geology model, obtaining specifications of proposed drilling equipment for use in the drilling of the well bore, and predicting a drilling mechanics in response to the specifications as a function of the geology characteristic per unit depth according to a prescribed drilling mechanics model. The geology characteristic includes at least rock strength. The specifications includes at least a bit specification of a recommended drill bit. Lastly, the predicted drilling mechanics include at least one of bit wear, mechanical efficiency, power, and operating parameters. A display is provided for generating a display of the geology characteristic and predicted drilling mechanics per unit depth, including either a display monitor or a printer.

Abstract: The present disclosure is directed to both a method and apparatus for providing data dynamically during the drilling of a borehole. This invention can be used with drilling apparatus which is commonly used to drill oil or gas wells, including wells which are vertically drilled or highly deviated wells. The invention provides measures of weight on the drill bit and other forces acting on a drill stem in the vicinity of the drill bit. The present invention is incorporated within the drill stem, which is powered from the surface by a typical rotary drilling rig. The associated drilling apparatus, however, further includes and incorporates a mud motor cooperating with a bent subsection of the sort normally used in drilling a borehole which deviates from the vertical. The downhole element of the invention consists of a subsection which is affixed in the drill stem in the vicinity of the drill bit, and preferably immediately above the drill bit.

Abstract: A downhole sensor sub is provided in the lower end of a drillstring, such sub having three orthogonally positioned accelerometers for measuring vibration of a drilling component such as the drill bit and/or the bottom hole assembly (BHA) along the X, Y and Z axes. The lateral acceleration is measured along either the X or Y axis and then analyzed in the frequency domain as to peak frequency and magnitude at such peak frequency. Backward whirling of the drilling component is indicated when the magnitude at the peak frequency exceeds a predetermined value. A low whirling frequency accompanied by a high acceleration magnitude based on empirically established values is associated with destructive vibration of the drilling component. One or more drilling parameters (weight on bit, rotary speed, etc.) is then altered to reduce or eliminate such destructive vibration.

Abstract: A method of assaying work of an earth boring bit of a given size and design comprises the steps of drilling a hole with the bit from an initial point to a terminal point and recording the distance between the initial and terminal points. A plurality of electrical incremental actual force signals are generated, each corresponding to a force of the bit over a respective increment of the distance between the initial and terminal points. A plurality of electrical incremental distance signals are also generated, each corresponding to the length of the increment for a respective one of the incremental actual force signals. The incremental actual force signals and the incremental distance signals are processed to produce a value corresponding to the total work done by the bit in drilling from the initial point to the terminal point. Using such a basic work assay, a number of other downhole occurrences and/or conditions can be assayed.

Abstract: The present invention provides a drilling system for directional drilling of boreholes. The system contains a drill string having a drill bit driven by a positive displacement mud motor. Sensors placed at selected locations in the drill string continually measure various downhole operating parameters, including the differential pressure across the mud motor, rotational speed of the mud motor, torque, temperature, pressure differential between the fluid passing through the mud motor and the annulas between the drill string and the borehole, and temperature of the circulating fluid. A downhole control circuit having a microprocessor and nonvolatile memory processes signals from these sensors and transmits the processed data uphole to a surface control unit via a suitable telemetry system. The surface control unit is programmed to operate the drilling system or aid an operator to control the drilling operations in any number of modes in response to the information provided by the various sensors.

Abstract: A method for evaluating formations and bit conditions is presented. The present invention processes signals indicative of downhole weight on bit (WOB), downhole torque (TOR), rate of penetration (ROP) and bit rotations (RPM), while taking into account bit geometry to provide a plurality of well logs and to optimize the drilling process. Drilling operations are monitored and adjusted in response to these processed signals and logs. The processed signals may include the following signals: drilling response, differential pressure, pore pressure, porosity, porosity compensated for formation effects, drilling alert, bit wear factor, abnormal torque, and bearing wear. The logs may include a drilling response log, a differential pressure log, a porosity log, a porosity log compensated for formation effects, a drilling alert log, a wear factor log, a torque analysis log and a bearing wear log.

Abstract: Hardware, software and methods for controlling the usage of well drill bits and other aspects of well drilling plans. At least a portion of a given well is drilled with a given drill bit. An abrasive-wear-affecting variable (drilling strength) for the lithology which has been most recently drilled with the bit is continually evaluated. The current abrasive wear of the bit by the total lithology which has been drilled thereby is continually calculated, based on the abrasive-wear-affecting variable. Continued use or retirement of the bit is controlled in accord with the wear calculation. Relative pore pressure at the current site of the drill bit is a useful by product which can be independently used to control other aspects of the well drilling plan, e.g. mud weight and the setting of casing.

Abstract: This invention is based on a new model describing the drilling process of a drag bit and concerns a method of determining the drilling conditions associated with the drilling of a borehole through subterranean formations, each one corresponding to a particular lithology, the borehole being drilled with a rotary drag bit, the method comprising the steps of: measuring the weight W applied on the bit, the bit torque T, the angular rotation speed .omega. of the bit and the rate of penetration .nu. of the bit to obtain sets of data (W.sub.i, T.sub.i, .nu..sub.i, .omega..sub.i) corresponding to different depths; calculating the specific energy E.sub.i and the drilling strength S.sub.i from the data (W.sub.i, T.sub.i, .nu..sub.i, .omega..sub.i); identifying at least one linear cluster of values (E.sub.i, S.sub.i), said cluster corresponding to a particular lithology; and determining the drilling conditions from said linear cluster.

Abstract: The invention relates to a method of monitoring the drilling of a borehole through an earth formation with a rotating drill bit fixed at the lower end of a drillstring. At least one physical quantity associated with the vibrations resulting from the interaction of the rotating drill bit with the earth formation is detected and an oscillatory signal is generated in response thereto. Filter coefficients a.sub.k of an auto-regressive filter model are determined by fitting the filter output signal with the oscillatory signal. The reflection coefficients of the vibrations propagating along the drill string and being reflected by a mis-match of impedance of two successive elements of the system earth formation/drillstring are derived from the filter coefficients. Finally, the hardness of the formation being drilled, the contact of the drillstring with the borehole and the vibration level of the vibration along the drillstring are determined from the reflection coefficients.

Abstract: A method is provided for generating an improved torque-drag model for at least the collar portion of the drill string in a directional oil or gas well. The techniques of the present invention determine the stiffness of incremental portions of the drill string, and uses this information, the borehole clearance, and the borehole trajectory to determine the contact locations between the drill string and the sidewalls of the well. The contact force at these determined locations can be calculated, taking into consideration all significant kinematic, external, and internal forces acting on that incremental portion of the drill string. More acurate torque-drag analysis provided by the improved model of the present invention assists in well planning, prediction, and control, assists in avoiding drilling problems, and reduces total costs for the well.

Abstract: A method is provided for determining the state of wear of a multicone drill bit. Vibrations generated by the working drill bit are detected and converted into a time oscillatory signal from which a frequency spectrum is derived. The periodicity of the frequency spectrum is extracted. The rate of rotation of at least one cone is determined from the periodicity and the state of wear of the drill bit is derived from the rate of cone rotation. The oscillatory signal represents the variation in amplitude of the vertical or torsional force applied to the drill bit. To extract periodicity, a set of harmonics in the frequency spectrum is given prominence by computing the cepstrum of the frequency spectrum or by obtaining an harmonic-enhanced spectrum. The fundamental frequency in the set of harmonics is determined and the rate of cone rotation is derived from the fundamental frequency.

Abstract: A method for determining the wear of cutting portion of a tool during drilling of a formation wherein a measurement is taken of the weight W applied to the tool and the torque T required to rotate said tool, the weight on the tool W and the torque T being linked by an equation of the type T=uW+vW.sup..alpha. in which u and v are parameters and .alpha. is a coefficient depending in part on the formation.

Abstract: A rotary drill bit is provided with cutting elements having a front layer of interbonded abrasive particles, such as synthetic diamonds, which layer has a thickness that varies with distance from the bit body. The characteristic relation thus obtained between bit agressiveness and bit wear can be used to monitor the bit wear condition during drilling.

Abstract: This invention relates to a method and apparatus for detecting excessive displacement of rotating cutter cones on rotary rock bits used in earth boring. The apparatus causes a detectable pressure change in the pressurized drilling fluid system triggered by a pre-determined displacement of a cone from its normal position. This is accomplished by penetration of a sensor by the displaced cone. In the simplest form the penetrated sensor forms an additional exit port for the drilling fluid thereby reducing pressure. In another embodiment the intact sensor maintains a nozzle restricting object in position within the bit body by a hydraulically actuated retainer penetration of the sensor permits loss of the hydraulic fluid and release of the restricting object which then restricts an exit port causing an immediate pressure increase.

Abstract: Downhole Torque and Rate of Penetration are utilized to develop indications of formations having high porosity or of the development of an undergauge bit. Downhole torque is normalized by dividing it by the product of downhole weight on bit and bit size to produce Dimensionless Torque while Rate of Penetration is normalized by dividing it by the product of downhole weight on bit and rotary speed. The values of Dimensionless Torque and Normalized Rate of Penetration are compared to "normally" expected values of these quantities. Deviations from the normal values are taken as an indication of the occurrence of bit penetration of a highly porous formation or of the development of an undergauge or damaged bit.

Abstract: Downhole torque and rate of penetration are utilized to develop indications of formations that are porous, argillaceous or tight. This information is useful as an aid in selecting drilling practices and drilling bits. The method separates bit effects from lithology effects when drilling with roller cone or PDC bits by utilizing surface and subsurface wellsite sensors to determine averaged values of real time penetration rate and downhole torque. Changes in bit torque are used to broadly classify the lithology into three categories: porous, argillaceous and tight formations while trends in bit torque and rate of penetration in shale are used to separate wear of the bit from changes in formation strength.

Abstract: Cutting insert for chip-removing machining comprising an upper face (11), a lower face (12) and, connecting those, edge surfaces (13). Lines of intersection between the edge surfaces and the upper face form cutting edges. The insert (10) has a substrate (14) comprising a metal and a photon-emitting material. The substrate (14) is covered by a photon-tight layer (15). During wear of the layer (15) the substrate (14) is exposed, and therefore the intensity and direction fo the photons can be detected for determination of the size and type of the wear damage.

Abstract: An earth drilling bit incorporating a tensioned linkage type bit wear indicator. A tensioned linkage extends through the bit between a wear sensor and a device for altering the resistance of the bit to receiving drilling fluid from the drill string. On detecting a predetermined degree of wear, the wear sensor releases the tension in the tensioned linkage. This activates the flow resistance altering device, causing the flow rate and/or pumping pressure of the drilling fluid to change. The tensioned linkage passes through two intersecting passageways in the bit. A guide element is inserted at the intersection of the two intersecting passageways. The guide element routes the tensioned linkage between the two passageways.

Abstract: An earth drilling bit incorporating a bit wear indicator. The bit wear indicator includes: a sensor to detect wear at a selected point on the bit; a device for altering the resistance of the bit to receiving drilling fluid from the drill string; and, a tensioned linkage extending between the wear sensor and the flow resistance altering means. On detecting a predetermined degree of wear, the wear sensor releases the tension in the tensioned linkage. This activates the flow resistance altering device, causing the flow rate and/or pumping pressure of the drilling fluid to change. This serves as a signal that the predetermined wear condition has been achieved. The bit wear indicator can be adapted to monitor many different types of bit wear, including bearing wear in roller-cone type bits and gauge wear in all types of bits.

Abstract: Information on tooth wear is obtained from the frequency distribution spectrum of a vibrational quantity influenced by the impact of cutter teeth on the bottom of a bore. For example, spectra may be obtained from the product of signals indicative of torque and torsional acceleration. Tooth wear is then indicated by the shift upwardly in frequency of peaks in the spectra. Other quantities which may be used, singly or together to enhance spectral information, are weight on bit, vertical acceleration, transverse acceleration, standpipe pressure. Abrupt changes in frequency distribution curves indicate abrupt occurrences such as broken teeth or stuck cones. A stuck cone is also indicated by unidirectional peaks in a plot of torsional acceleration against time.

Abstract: A cutting cone on a rotary rock bit is captively retained on a journal pin by an annular array of ball bearings disposed in laterally facing annular races formed in the cone and pin. When a predetermined amount of surface wear has occurred between the cone and pin as the bit is operated, one or more of the balls is caused to axially shift into and become trapped in a small lockup grooved formed in the journal pin and communicating with its race. Other balls become wedged between the trapped balls and the cone, thereby rotationally locking the cone on its pin and preventing further pin-cone surface wear which might otherwise cause cone loss. During operation of the bit, the locked cone produces a readily detectable increase in rotary table torque, and a decrease in bit penetration rate, thereby signalling the driller that the bit needs replacement.